The production of crude oil from a formation involves a broad range of techniques and equipment. One such production technique is that of using a "down hole" pump submerged in a well containing formation fluid which is reciprocatively driven to lift the fluid through a tubing string to the well head from where it is piped to separation and storage facilities. Classically, a walking beam and more recently an improved hydraulic stroking device at the surface reciprocates the pump.
In a gas driven formation the formation fluid generally includes a mixture of water, oil, free gas, and gas which has been forced into solution by formation pressure. As pumping of the well occurs, formation pressure may be gradually reduced. Because of this reduced formation pressure and pressure changes occurring within the pump, outgassing of some of the gas in solution can occur as the formation fluid enters the pump. This outgassed fluid may combine with free gas in the mixture to form a pocket of gas in the pump. For the pump to continue to function, such gas must be pumped up the tubing string with the liquid portion of the formation fluid. However, in order for the gas to move into the tubing string, it must be compressed to the pressure of the fluid in the tubing string which can be over 2,000 psi. Because pumps submerged in wells operate under adverse conditions which necessitate relatively large clearances between moving parts and which militate against using seals between moving parts, they are inefficient gas compressors. In consequence the pumps often become gas-locked, i.e., they continue to reciprocate back and forth but with no pumping effect. The gas pocket cannot be compressed to the extent it can be pumped up the tubing string and the pressure in the pump cannot be lowered to a state wherein more fluid can be drawn into the pump to displace the gas pocket.
A gas locked pump remains in that locked state until formation pressure builds back up to where more fluid can be forced into the pump and the gas pocket can be displaced up the tubing string. Most producers using conventional walking beam stroking devices cannot detect a gas locked pump. Consequently, the pump may be operated for long periods of time in a gas locked state. Operating a pump in such a state results in wasted energy, reduced production, and additional wear of the pump and stroking device.
To reduce gas lock, manufacturers have attempted to achieve higher gas compression efficiencies. This has resulted in more elaborate pumps. Furthermore, when gas can be pumped up the tubing string, the resulting liquid-gas mixture at the well head may be a foam that resembles a "dirty milkshake". When the gas in this foam dissipates, only a small volume of liquid remains. The volume of this liquid may be as little as 10 percent of the pumped fluid. Thus, the amount of liquid produced at the well head may be only 10 percent of the volume of fluid pumped. Obviously, the efficiency of the pumping process is seriously degraded when gas is pumped up the tubing string.
Using a hydraulic stroking device rather than a walking beam stroking device, a capability has been realized for monitoring the performance of an operating pump. Thus, it has been found possible to detect gas pockets in a pump. Investigations have determined that reducing the stroking rate of the pump substantially eliminates gas in the pump and greatly increases the efficiency of the pumping process. Unfortunately, when this lower stroking rate technique has been employed, production has fallen to unacceptable levels.
In view of the foregoing, it will be appreciated that the stroking rate of the pump will be an important factor in any solution to the problem of gas occurring in a pump operating in a well in a gas driven formation, e.g., the Clinton formation. Such solution preferably will solve the problem of gas in a pump in such a manner that gas will not have to be pumped up the tubing string.